1. Field of the Invention
The present invention relates to rotary drag bits for drilling subterranean formations and their operation. More specifically, the present invention relates to the design of such bits for optimum performance in the context of controlling cutter loading and depth-of-cut without generating an excessive amount of torque-on-bit should the weight-on-bit be increased to a level which exceeds the optimal weight-on-bit for the current rate-of-penetration of the bit.
2. State of the Art
Rotary drag bits employing polycrystalline diamond compact (PDC) cutters have been employed for several decades. PDC cutters are typically comprised of a disc-shaped diamond xe2x80x9ctablexe2x80x9d formed on and bonded under high-pressure and high-temperature conditions to a supporting substrate such as cemented tungsten carbide (WC), although other configurations are known. Bits carrying PDC cutters, which for example, may be brazed into pockets in the bit face, pockets in blades extending from the face, or mounted to studs inserted into the bit body, have proven very effective in achieving high rates of penetration (ROP) in drilling subterranean formations exhibiting low to medium compressive strengths. Recent improvements in the design of hydraulic flow regimes about the face of bits, cutter design, and drilling fluid formulation have reduced prior, notable tendencies of such bits to xe2x80x9cballxe2x80x9d by increasing the volume of formation material which may be cut before exceeding the ability of the bit and its associated drilling fluid flow to clear the formation cuttings from the bit face.
Even in view of such improvements, however, PDC cutters still suffer from what might simply be termed xe2x80x9coverloadingxe2x80x9d even at low weight-on-bit (WOB) applied to the drill string to which the bit carrying such cutters is mounted, especially if aggressive cutting structures are employed. The relationship of torque to WOB may be employed as an indicator of aggressivity for cutters, so the higher the torque to WOB ratio, the more aggressive the cutter. This problem is particularly significant in low compressive strength formations where an unduly great depth of cut (DOC) may be achieved at extremely low WOB. The problem may also be aggravated by drill string bounce, wherein the elasticity of the drill string may cause erratic application of WOB to the drill bit, with consequent overloading. Moreover, operating PDC cutters at an excessively high DOC may generate more formation cuttings than can be consistently cleared from the bit face and back up the bore hole via the junk slots on the face of the bit by even the aforementioned improved, state-of-the-art bit hydraulics, leading to the aforementioned bit balling phenomenon.
Another, separate problem involves drilling from a zone or stratum of higher formation compressive strength to a xe2x80x9csofterxe2x80x9d zone of lower strength. As the bit drills into the softer formation without changing the applied WOB (or before the WOB can be changed by the directional driller), the penetration of the PDC cutters, and thus the resulting torque on the bit (TOB), increase almost instantaneously and by a substantial magnitude. The abruptly higher torque, in turn, may cause damage to the cutters and/or the bit body itself. In directional drilling, such a change causes the tool face orientation of the directional (measuring-while-drilling, or MWD, or a steering tool) assembly to fluctuate, making it more difficult for the directional driller to follow the planned directional path for the bit. Thus, it may be necessary for the directional driller to back off the bit from the bottom of the borehole to reset or reorient the tool face. In addition, a downhole motor, such as drilling fluid-driven Moineau-type motors commonly employed in directional drilling operations in combination with a steerable bottomhole assembly, may completely stall under a sudden torque increase. That is, the bit may stop rotating thereby stopping the drilling operation and again necessitating backing off the bit from the borehole bottom to re-establish drilling fluid flow and motor output. Such interruptions in the drilling of a well can be time consuming and quite costly.
Numerous attempts using varying approaches have been made over the years to protect the integrity of diamond cutters and their mounting structures and to limit cutter penetration into a formation being drilled. For example, from a period even before the advent of commercial use of PDC cutters, U.S. Pat. No. 3,709,308 discloses the use of trailing, round natural diamonds on the bit body to limit the penetration of cubic diamonds employed to cut a formation. U.S. Pat. No. 4,351,401 discloses the use of surface set natural diamonds at or near the gage of the bit as penetration limiters to control the depth-of-cut of PDC cutters on the bit face. The following other patents disclose the use of a variety of structures immediately trailing PDC cutters (with respect to the intended direction of bit rotation) to protect the cutters or their mounting structures: U.S. Pat. Nos. 4,889,017; 4,991,670; 5,244,039 and 5,303,785. U.S. Pat. No. 5,314,033 discloses, inter alia, the use of cooperating positive and negative or neutral backrake cutters to limit penetration of the positive rake cutters into the formation. Another approach to limiting cutting element penetration is to employ structures or features on the bit body rotationally preceding (rather than trailing) PDC cutters, as disclosed in U.S. Pat. Nos. 3,153,458; 4,554,986; 5,199,511 and 5,595,252.
In another context, that of so-called xe2x80x9canti-whirlxe2x80x9d drilling structures, it has been asserted in U.S. Pat. No. 5,402,856 to one of the inventors herein that a bearing surface aligned with a resultant radial force generated by an anti-whirl underreamer should be sized so that force per area applied to the borehole sidewall will not exceed the compressive strength of the formation being underreamed. See also U.S. Pat. Nos. 4,982,802; 5,010,789; 5,042,596; 5,111,892 and 5,131,478.
While some of the foregoing patents recognize the desirability to limit cutter penetration, or DOC, or otherwise limit forces applied to a borehole surface, the disclosed approaches are somewhat generalized in nature and fail to accommodate or implement an engineered approach to achieving a target ROP in combination with more stable, predictable bit performance. Furthermore, the disclosed approaches do not provide a bit or method of drilling which is generally tolerant to being axially loaded with an amount of weight-on-bit over and in excess what would be optimum for the current rate-of-penetration for the particular formation being drilled and which would not generate high amounts of potentially bit-stopping or bit-damaging torque-on-bit should the bit nonetheless be subjected to such excessive amounts of weight-on-bit.
The present invention addresses the foregoing needs by providing a well-reasoned, easily implementable bit design particularly suitable for PDC cutter-bearing drag bits, which bit design may be tailored to specific formation compressive strengths or strength ranges to provide DOC control in terms of both maximum DOC and limitation of DOC variability. As a result, continuously achievable ROP may be optimized and torque controlled even under high WOB, while destructive loading of the PDC cutters is largely prevented.
The bit design of the present invention employs depth of cut control (DOCC) features which reduce, or limit, the extent in which PDC cutters, or other types of cutters or cutting elements, are exposed on the bit face, on bladed structures, or as otherwise positioned on the bit. The DOCC features of the present invention provide substantial area on which the bit may ride while the PDC cutters of the bit are engaged with the formation to their design DOC, which may be defined as the distance the PDC cutters are effectively exposed below the DOCC features. Stated another way, the cutter standoff is substantially controlled by the effective amount of exposure of the cutters above the surface, or surfaces, surrounding each cutter. Thus, by constructing the bit so as to limit the exposure of at least some of the cutters on the bit, such limited exposure of the cutters in combination with the bit providing ample surface area to serve as a xe2x80x9cbearing surfacexe2x80x9d in which the bit rides as the cutters engage the formation at their respective design DOC enables a relatively greater DOC (and thus ROP for a given bit rotational speed) than with a conventional bit design without the adverse consequences usually attendant thereto. Therefore the DOCC features of the present invention preclude a greater DOC than that designed for by distributing the load attributable to WOB over a sufficient surface area on the bit face, blades or other bit body structure contacting the formation face at the borehole bottom so that the compressive strength of the formation will not be exceeded by the DOCC features. As a result, the bit does not substantially indent, or fail, the formation rock.
Stated another way, the present invention limits the unit volume of formation material (rock) removed per bit rotation to prevent the bit from over-cutting the formation material and balling the bit or damaging the cutters. If the bit is employed in a directional drilling operation, tool face loss or motor stalling is also avoided.
In one embodiment, a rotary drag bit preferably includes a plurality of circumferentially spaced blade structures extending along the leading end or formation engaging portion of the bit generally from the cone region approximate the longitudinal axis, or centerline, of the bit, upwardly to the gage region, or maximum drill diameter of bit. The bit further includes a plurality of superabrasive cutting elements, or cutters such as PDC cutters, preferably disposed on radially outward facing surfaces of preferably each of the blade structures. In accordance with the DOCC aspect of the present invention, each cutter positioned in at least the cone region of the bit, e.g., those cutters which are most radially proximate the longitudinal centerline and thus are generally positioned radially inward of a shoulder portion of the bit, are disposed in their respective blade structures in such a manner that each of such cutters is exposed only to a limited extent above the radially outwardly facing surface of the blade structures in which the cutters are associatively disposed. That is, each of such cutters exhibit a limited amount of exposure generally perpendicular to the selected portion of the formation-facing surface in which the superabrasive cutter is secured to control the effective depth-of-cut of at least one superabrasive cutter into a formation when the bit is rotatingly engaging a formation such as during drilling. By so limiting the amount of exposure of such cutters by, for example, the cutters being secured within and substantially encompassed by cutter-receiving pockets, or cavities, the DOC of such cutters into the formation is effectively and individually controlled. Thus, regardless of the amount of WOB placed, or applied, on the bit, even if the WOB exceeds what would be considered an optimum amount for the hardness of the formation being drilled and the ROP in which the drill bit is currently providing, the resulting torque, or TOB, will be controlled or modulated. Thus, because such cutters have a reduced amount of exposure above the respective formation-facing surface in which it is installed, especially as compared to prior art cutter installation arrangements, the resultant TOB generated by the bit will be limited to a maximum, acceptable value. This beneficial result is attributable to the DOCC features, or characteristic, of the present invention effectively preventing at least a sufficient number of the total number of cutters from over-engaging the formation and potentially causing the rotation of the bit to slow or stall due to an unacceptably high amount of torque being generated. Furthermore, the DOCC features of the present invention are essentially unaffected by excessive amounts of WOB, as there will preferably be a sufficient amount or size of bearing surface area devoid of cutters on at least the leading end of the bit in which the bit may xe2x80x9cridexe2x80x9d upon the formation to inhibit or prevent a torque-induced bit stall from occurring.
Optionally, bits employing the DOCC aspects of the present invention may have reduced exposure cutters positioned radially more distant than those cutters proximate to the longitudinal centerline of the bit such as in the cone region. To elaborate, cutters having reduced exposure may be positioned in other regions of a drill bit embodying the DOCC aspects of the present invention. For example, reduced exposure cutters positioned on the comparatively more radially distant nose, shoulder, flank, and gage portions of a drill bit will exhibit a limited amount of cutter exposure generally perpendicular to the selected portion of the radially outwardly facing surface to which each of the reduced exposure cutters are respectively secured. Thus, the surfaces carrying and proximately surrounding each of the additional reduced exposure cutters will be available to contribute to the total combined bearing surface area on which the bit will be able to ride upon the formation as the respective maximum depth-of-cut for each additional reduced exposure cutter is achieved depending upon the instant WOB and the hardness of the formation being drilled.
By providing DOCC features having a cumulative surface area sufficient to support a given WOB on a given rock formation preferably without substantial indentation or failure of same, WOB may be dramatically increased, if desired, over that usable in drilling with conventional bits without the PDC cutters experiencing any additional effective WOB after the DOCC features are in full contact with the formation. Thus, the PDC cutters are protected from damage and, equally significant, the PDC cutters are prevented from engaging the formation to a greater depth of cut and consequently generating excessive torque which might stall a motor or cause loss of tool face orientation.
The ability to dramatically increase WOB without adversely affecting the PDC cutters also permits the use of WOB substantially above and beyond the magnitude applicable without the adverse effects associated with conventional bits to maintain the bit in contact with the formation, reduce vibration and enhance the consistency and depth of cutter engagement with the formation. In addition, drill string vibration as well as dynamic axial effects, commonly termed xe2x80x9cbounce,xe2x80x9d of the drill string under applied torque and WOB may be damped so as to maintain the design DOC for the PDC cutters. Again, in the context of directional drilling, this capability ensures maintenance of tool face and stall-free operation of an associated downhole motor driving the bit.
It is specifically contemplated that the DOCC features according to the present invention may be applied to coring bits as well as full bore drill bits. As used herein, the term xe2x80x9cbitxe2x80x9d encompasses core bits and other special purpose bits. Such usage may be, by way of example only, particularly beneficial when coring from a floating drilling rig, or platform, where WOB is difficult to control because of surface water wave-action-induced rig heave. When using the present invention, a WOB in excess of that normally required for coring may be applied to the drill string to keep the core bit on bottom and maintain core integrity and orientation.
It is also specifically contemplated that the DOCC attributes of the present invention have particular utility in controlling, and specifically reducing, torque required to rotate rotary drag bits as WOB is increased. While relative torque may be reduced in comparison to that required by conventional bits for a given WOB by employing the DOCC features at any radius or radii range from the bit centerline, variation in placement of DOCC features with respect to the bit centerline may be a useful technique for further limiting torque since the axial loading on the bit from applied WOB is more heavily emphasized toward the centerline and the frictional component of the torque is related to such axial loading. Accordingly, the present invention optionally includes providing a bit in which the extent of exposure of the cutters vary with respect to the cutters respective positions on the face of the bit. As an example, one or more of the cutters positioned in the cone, or the region of the bit proximate the centerline of the bit, are exposed to a first extent, or amount, to provide a first DOC and one or more cutters positioned in the more radially distant nose and shoulder regions of the bit are exposed at a second extent, or amount, to provide a second DOC. Thus, a specifically engineered DOC profile may be incorporated into the design of a bit embodying the present invention to customize, or tailor, the bit""s operational characteristics in order to achieve a maximum ROP while minimizing and/or modulating the TOB at the current WOB, even if the WOB is higher than what would otherwise be desired for the ROP and the specific hardness of the formation then being drilled.
Furthermore, bits embodying the present invention may include blade structures in which the extent of exposure of each cutter positioned on each blade structure has a particular and optionally individually unique DOC, as well as individually selected and possibly unique effective backrake angles, thus resulting in each blade of the bit having a preselected DOC cross-sectional profile as taken longitudinally parallel to the centerline of the bit and taken radially to the outermost gage portion of each blade. Moreover, a bit incorporating the DOCC features of the present invention need not have cutters installed on, or carried by, blade structures, as cutters having a limited amount of exposure perpendicular to the exterior of the bit in which each cutter is disposed may be incorporated on regions of bits in which no blade structures are present. That is, bits incorporating the present invention may be completely devoid of blade structures entirely, such as, for example, a coring bit.
A method of constructing a drill bit in accordance with the present invention is additionally disclosed herein. The method includes providing at least a portion of the drill bit with at least one cutting element-accommodating pocket, or cavity, on a surface which will ultimately face and engage a formation upon the drill bit being placed in operation. The method of constructing a bit for drilling subterranean formations includes disposing within at least one cutter-receiving pocket a cutter exhibiting a limited amount of exposure perpendicular to the formation-facing surface proximate the cutter upon the cutter being secured therein. Optionally, the formation-facing surface may be built up by a hard facing, a weld, a weldment, or other material being disposed upon the surface surrounding the cutter so as to provide a bearing surface of a sufficient size while also limiting the amount of cutter exposure within a preselected range to effectively control the depth of cut that the cutter may achieve upon a certain WOB being exceeded and/or upon a formation of a particular compressive strength being encountered.
A yet further option is to provide wear knots, or structures, formed of a suitable material which extend outwardly and generally perpendicularly from the face of the bit in general proximity of at least one or more of the reduced exposure cutters. Such wear knots may be positioned rotationally behind, or trailing, each provided reduced exposure cutter so as to augment the DOCC aspects provided by the bearing surface respectively carrying and proximately surrounding a significant portion of each reduced exposure cutter. Thus, the optional wear knots, or wear bosses, provide a bearing surface area in which the drill bit may ride on the formation upon the maximum DOC of that cutter being obtained for the present formation hardness and then current WOB. Such wear knots, or bosses, may comprise hard facing material, structure provided when casting or molding the bit body or, in the case of steel-bodied bits, may comprise weldments, structures secured to the bit body by methods known within the art of subterranean drill bit construction, or by surface welds in the shape of one or more weld-beads or other configurations or geometries.
A method of drilling a subterranean formation is further disclosed. The method for drilling includes engaging a formation with at least one cutter and preferably a plurality of cutters in which one or more of the cutters each exhibit a limited amount of exposure perpendicular to a surface in which each cutter is secured. In one embodiment, several of the plurality of limited exposure cutters are positioned on a formation-facing surface of at least one portion, or region, of at least one blade structure to render a cutter spacing and cutter exposure profile for that blade and preferably for a plurality of blades that will enable the bit to engage the formation within a wide range of WOB without generating an excessive amount of TOB, even at elevated WOBs, for the instant ROP in which the bit is providing. The method further includes an alternative embodiment in which the drilling is conducted with primarily only the reduced exposure cutters engaging a relatively hard formation within a selected range of WOB and upon a softer formation being encountered and/or an increased amount of WOB being applied, at least one bearing surface surrounding at least one reduced, or limited, exposure cutter, and preferably a plurality of sufficiently sized bearing surfaces respectively surrounding a plurality of reduced exposure cutters, contacts the formation and thus limits the DOC of each reduced, or limited, exposure cutter while allowing the bit to ride on the bearing surface, or bearing surfaces, against the formation regardless of the WOB being applied to the bit and without generating an unacceptably high, potentially bit damaging TOB for the current ROP.